Natural gas, as it is captured from naturally occurring deposits, is composed primarily of light aliphatic hydrocarbons such as methane, propane, butane, pentane, and their isomers. Certain contaminants are naturally present in the gas, and must be removed prior to delivery of the purified gas for private use or commercial conditioning. These contaminants include aliphatic hydrocarbons having 4 carbon atoms or more (C4+) and aromatic hydrocarbons such as benzene, toluene, ethyl benzene and xylenes collectively referred to as “BTX”, but more importantly acid components such as hydrogen sulfide (H2S) and carbon dioxide (CO2).
The presence of hydrogen sulfide in industrial gases causes significant environmental problems and is detrimental to the plant structure, requiring constant maintenance. Strict requirements are therefore in place to remove H2S from gas streams, in particular in natural gas plants.
Removal and disposal of H2S from natural gas is customarily accomplished by contacting the natural gas containing the H2S with a liquid amine solvent at the pressure of the natural gas, which is usually from 40 to 100 bar (considered “high pressure”), thus having the H2S adsorbed by the amine solvent. Carbon dioxide (CO2), aromatic hydrocarbons and C4+ aliphatic hydrocarbons are simultaneously adsorbed by the amine solvent due to the high pressure maintained during the absorption of H2S. A “sweet” or purified natural gas meeting environmental standards is thus obtained and an amine containing most of the contaminants (CO2, H2S, aromatic hydrocarbons and C4+ aliphatic hydrocarbons) is recovered. The contaminated amine solvent is then carried to a regeneration zone where it is recovered under elevated temperature (generally about 130° C.) and low pressure conditions (generally about 2 to 3 barA). An acid gas containing CO2, H2S, aromatic hydrocarbons and C4+ aliphatic hydrocarbons is also obtained.
The presence of H2S in the acid gas obtained after purification of natural gas remains problematic and sulfur recovery units (SRU) are thus installed to convert poisonous sulfur compounds, as H2S, into harmless elemental sulfur.
A widespread method for desulfurization of H2S-containing gas streams is the Claus process which operates in two major process steps. The first process step is carried out in a furnace where hydrogen sulfide is converted to elemental sulfur and sulfur dioxide at temperatures of approximately 1100 to 1400° C. by the combustion of about one third of the hydrogen sulfide in the gas stream. The so obtained sulfur dioxide reacts with hydrogen sulfide in the furnace to elemental sulfur by Claus reaction. Thus, in this first step of the Claus process, about 60 to 70% of the H2S in the feed gas are converted and most of the aromatic and C4+ aliphatic hydrocarbons are eliminated.
To achieve higher sulfur recovery rates, at least one catalytic step follows where the Claus reaction according to Eq. 1:2H2S+SO2↔3/xSx+2H2O  Eq. 1continues.
The Claus process is very well adapted to acid gas feeds containing more than 55 mol. % of H2S where the first combustion step operated at a temperature higher than 1200° C. can be fully conducted thus converting 60 to 70% of H2S and simultaneously destroying the aromatic hydrocarbons and C4+ aliphatic hydrocarbons. However, recovering sulfur from an acid gas feed containing less than 55 mol. % of H2S applying the Claus process happens to be more complicated: the first combustion step cannot be conducted at sufficiently elevated temperatures or cannot be conducted at all due to the presence of significant amounts of CO2 in the feed that cools down the combustion reaction below 1100° C. or even inhibits the combustion reaction when the content of CO2 exceeds 85%. This allows the aromatic hydrocarbons and C4+ aliphatic hydrocarbons to avoid combustion in the first thermal step of the Claus process and to pass unreacted in the catalytic step. These aromatic hydrocarbons and C4+ aliphatic hydrocarbons are however harmful to the installed unit because they deactivate the catalysts operated in the catalytic step of the Claus process. This results in poor sulfur recovery and frequent catalyst replacement.
Several methods have been investigated in order to remove aromatic hydrocarbons and C4+ aliphatic hydrocarbons from lean acid gas feeds containing less than 55 mol. % of H2S to make them suitable for sulfur plants. For example, acid gas enrichment (AGE) processes where the lean acid gas (obtained from the regeneration zone generally operated at about 130° C. and 2 to 3 barA), is treated in an absorber at its pressure of 3 barA (considered “low pressure”) using a selective solvent can be performed. Due to the “low pressure” operated in the AGE, the solvent preferentially absorbs H2S over CO2, and much lower levels of aromatic hydrocarbons and C4+ aliphatic hydrocarbons. After regeneration of the solvent, an acid gas enriched in H2S and depleted CO2, aromatic hydrocarbons and C4+ aliphatic hydrocarbons is obtained. AGE processes is usually selected when it can increase the H2S content in the acid gas over 55 vol. % allowing the obtained acid gas to be treated conventionally by Claus, with treatment in a Claus furnace at temperatures higher than 1100° C., thus eliminating the aromatic hydrocarbons and C4+ aliphatic hydrocarbons prior to the Claus catalytic step. Application EP2402068 for example discloses the treatment of acid gases with two absorption steps. In this process, the solvent enriched in H2S obtained from the first absorption zone is sent to a desorption zone where heat is supplied to desorb H2S and promote formation of H2S-enriched gas. A portion of this of H2S-enriched gas is then sent to another H2S absorption zone for further enrichment. AGE however can be found unsatisfactory when the initial concentration of H2S in the acid gas is too low (usually less than 20 mol. %) to reach a concentration higher than 55 mol. % of H2S after enrichment.
Another proposed solution for aromatic and C4+ aliphatic hydrocarbons removal is the gas stripping process, conventionally fuel gas stripping, of a rich amine solvent obtained from “high pressure” sour natural gas absorber before its regeneration. The fuel gas stream will strip off the aromatic and C4+ aliphatic hydrocarbons of the lean acid gas and an amine solvent depleted in aromatic and C4+ aliphatic hydrocarbons will thus be obtained. The fuel gas containing the aromatic and C4+ aliphatic hydrocarbons will be used as a combustible for an incinerator or a utility boiler where the pollutants will be destructed. However, in such gas stripping processes, the removal of the aromatic and C4+ aliphatic hydrocarbons from the rich amine is a function of stripping fuel gas flow rate: the higher the fuel gas flowrate, the more removal can be achieved. The fuel gas, however, is used in the unit as a feed for an incinerator and/or utility boilers and, its flowrate thus remains limited by the demand of the incinerator or utility boilers. In order to properly remove the aromatic and C4+ aliphatic hydrocarbons, it could be necessary to use important amounts of fuel gases, much higher than what would be necessary to run the incinerator and/or utility boilers. This would thus result in high waste of fuel gas, particularly when the content of aromatics and aliphatic hydrocarbons is high in rich amine solvent obtained from “high pressure” sour natural gas absorber. In this context, the fuel gas stripping would not provide a satisfactory solution to the problem of aromatic and C4+ aliphatic hydrocarbons removal from lean acid gas prior to sulfur recovery.
A further option considered in industry is the adsorption of the aromatic hydrocarbons and C4+ aliphatic hydrocarbons from the acid gas in regenerable activated carbon beds or molecular sieves. Although technically feasible, these processes however remain costly due to the necessary regeneration cycles of the carbon beds and the difficulties to valorize the products issued from these regenerations due to the presence of pollutants such as H2S.
Thus, there remains a need for a process that efficiently removes aromatic hydrocarbons, such as benzene, toluene, ethyl benzene and xylene (BTX) and aliphatic hydrocarbons having 4 carbon atoms or more (C4+) from a lean acid gas containing less than 20 mol. % of H2S prior to sulfur recovery, when AGE cannot achieve sufficient H2S enrichment.
The object of the present invention a process for the removal of aromatic hydrocarbons, such as benzene, toluene, ethyl benzene and xylene (BTX) and aliphatic hydrocarbons having 4 carbon atoms or more (C4+) from a lean acid gas containing CO2 and less than 20 mol. % of H2S, which process comprises:
a) contacting the lean acid gas stream (1) with a H2S-selective liquid absorbent solution (29) in a first absorption zone (2) to produce a gas stream depleted in H2S (3) and containing CO2, aromatic hydrocarbons and C4+ aliphatic hydrocarbons, and an absorbent solution enriched in H2S (4), also containing co-absorbed C4+ aliphatic hydrocarbons, aromatic hydrocarbons and CO2,
b) introducing the absorbent solution enriched in H2S (4) into a non-thermic stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain an absorbent solution depleted in C4+ aliphatic hydrocarbons and aromatic hydrocarbons (9) and containing H2S and CO2 and a stripping gas stream enriched in aromatic hydrocarbons and C4+ aliphatic hydrocarbons (10), also containing H2S and CO2,
c) contacting the stripping gas stream enriched in aromatic hydrocarbons and C4+ aliphatic hydrocarbons (10), also containing H2S and CO2 obtained in step b) with a H2S-selective liquid absorbent solution (28) in a second absorption zone (12) to obtain a stripping gas stream depleted in H2S and containing aromatic hydrocarbons, C4+ aliphatic hydrocarbons and CO2 (13), and an absorbent solution enriched in H2S (14) also containing co-absorbed aromatic hydrocarbons, C4+ aliphatic hydrocarbons and CO2, said H2S-selective liquid absorbent solution being preferably identical to that used in step a),
d) introducing the absorbent solution depleted in C4+ aliphatic hydrocarbons and aromatic hydrocarbons (9) obtained in step b) into a desorption zone (16) wherein the H2S-selective liquid absorbent solution (17) is recovered and a lean acid gas containing H2S and CO2, depleted in C4+ aliphatic hydrocarbons and aromatic hydrocarbons (21) is produced.
The invention is also directed to a process for sulfur recovery from a lean acid gas containing CO2 and less than 20 mol. % of H2S, which process comprises:
i) pretreating the lean acid gas stream (1) for the removal of aromatic hydrocarbons and C4+ aliphatic hydrocarbons according to the above described process to obtain a lean acid gas depleted in C4+ aliphatic hydrocarbons and aromatic hydrocarbons (21) or (26),
ii) mixing at least part of the pretreated lean acid gas depleted in C4+ aliphatic hydrocarbons and aromatic hydrocarbons (21) or (26) with an oxygen containing gas, for example air, to obtain a gas stream containing both H2S and oxygen,
iii) optionally introducing part of the obtained lean acid gas depleted in aromatic hydrocarbons (21) or (26) and oxygen into a furnace to recover elemental sulfur,
iv) passing the lean acid gas depleted in C4+ aliphatic hydrocarbons and aromatic hydrocarbons recovered from step ii) and optionally step iii), after having optionally being preheated, into a catalytic reactor containing a catalyst system which catalyzes the direct oxidation of H2S with oxygen and/or the Claus reaction of H2S with sulfur dioxide (SO2) so as to recover a lean acid gas stream depleted in H2S and elemental sulfur.